Method to perform rapid formation fluid analysis

ABSTRACT

A method for determining a property of a formation is described herein. The method includes positioning a wellbore tool at a location within a wellbore. A formation fluid is withdrawn from the formation using the wellbore tool. The formation fluid is passed through a flow line within the wellbore tool and a formation fluid sample is extracted from the flow line. The method further includes analyzing the formation fluid sample within the wellbore tool to determine a property of the formation fluid sample. The analysis is performed by excluding mud filtrate contamination within the flow line.

TECHNICAL FIELD

This disclosure relates to fluid analysis, and more particularly toformation fluid analysis.

BACKGROUND

Wireline logging is used in the oil and gas field industry toinvestigate and determine properties of hydrocarbon reservoirformations. A wireline logging operation begins by lowering a wirelinetool into a wellbore that traverses a formation. The wireline toolincludes a probe for extracting formation fluid from the formation andpumping the formation fluid into the wireline tool. In one example, thisformation fluid is then optically analyzed to determine a chemicalcomposition for the fluid. This data provides valuable information aboutthe hydrocarbon reservoir formation that can be used later in completingand producing the well.

The optical analysis is performed using a “clean” formation fluid, whichmay take a great deal of time to obtain due to mud filtratecontamination within the formation. The mud filtrate contamination comesfrom drilling mud within the wellbore. The drilling mud can be oil-basedor water-based. In many cases, the drilling mud penetrates a distanceinto the wellbore and contaminates the formation fluid. This mudfiltrate contamination can invalidate an optical analysis. For example,oil-based mud filtrate within the sample can cause inflated values oflumped alkanes with carbon numbers equal to or greater than six (e.g.,C₆₊ fraction). Furthermore, mud filtrate within the sample can causeoptical scattering from mud particulates and emulsions (e.g., oil/watermixtures), which can also invalidate an optical analysis.

To obtain a clean sample for analysis, the wireline tool continuouslyextracts formation fluid from the formation and pumps the formationfluid through the tool. Eventually, due to the limited penetrationdistance of the drilling mud into the formation, the formation fluidentering the wireline tool will “clean up” and will no longer contain asubstantial amount of mud filtrate. The analysis can then be performedon this “clean” sample of formation fluid. The cleanup time may varybetween an hour and 24 hours. The total cleanup time is compounded whencleanup is repeated at multiple sampling locations within the formation.These extended cleanup times make wireline logging operations timeconsuming. In some cases, such as wireline logging operation performedon offshore rigs, the extended cleanup times make wireline loggingoperations prohibitively expensive.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

Illustrative embodiments are directed to a method for determining aproperty of a formation. The method includes positioning a wellbore toolat a location within a wellbore. A formation fluid is withdrawn from theformation using the wellbore tool. The formation fluid is passed througha flow line within the wellbore tool and a formation fluid sample isextracted from the flow line. The method further includes analyzing theformation fluid sample within the wellbore tool to determine a propertyof the formation fluid sample. The analysis is performed by excludingmud filtrate contamination within the flow line. Thus, in some cases,the analysis is performed before the formation fluid within the flowline has “cleaned up” and while there is still substantial mud filtratecontamination within the flow line.

Various embodiments are also directed to another method for determininga property of a formation contaminated with water-based mud filtrate. Inthis method, a wellbore tool is positioned at a location within awellbore and a formation fluid is withdrawn from the formation using thewellbore tool. The formation fluid is passed through a flow line withinthe wellbore tool and a formation fluid sample is extracted from theflow line. Water is removed from the formation fluid sample using amembrane and the formation fluid sample is analyzed within the wellboretool to determine a property of the formation fluid sample.

Further illustrative embodiments are also directed to another method fordetermining a property of a formation contaminated with oil-based mudfiltrate. The method includes positioning a wellbore tool at a locationwithin a wellbore and withdrawing a formation fluid from the formationusing the wellbore tool. The formation fluid is passed through a flowline within the wellbore tool and a formation fluid sample is extractedfrom the flow line. The method also includes identifying a number ofchemical components within the formation fluid sample using gaschromatography. Chemical components that appear or may appear within theoil-based mud filtrate are excluded from consideration. A remaining setof chemical components from the number of chemical components is used todetermine a property of the formation fluid sample.

BRIEF DESCRIPTION OF THE DRAWINGS

Those skilled in the art should more fully appreciate advantages ofvarious embodiments of the present disclosure from the following“Description of Illustrative Embodiments,” discussed with reference tothe drawings summarized immediately below.

FIG. 1 shows a wireline logging system at a well site in accordance withone embodiment of the present disclosure;

FIG. 2 shows a wireline tool in accordance with one embodiment of thepresent disclosure;

FIG. 3A shows a fluid analyzer module in accordance with one embodimentof the present disclosure;

FIG. 3B shows a fluid analyzer module in accordance with anotherembodiment of the present disclosure;

FIG. 4 shows a method for determining a property of a formation inaccordance with one embodiment of the present disclosure;

FIG. 5 shows a method for determining a property of a formationcontaminated with an oil-based mud filtrate in accordance with oneembodiment of the present disclosure;

FIG. 6A shows (i) a reference chromatogram that was obtained byanalyzing a formation fluid sample and (ii) a contaminated chromatogramthat was obtained by analyzing the same formation fluid samplecontaminated with an oil-based mud filtrate in accordance with oneembodiment of the present disclosure;

FIG. 6B shows a more detailed view of the chromatograms of FIG. 6A.

FIG. 7 shows a method for determining a property of a formation that iscontaminated by a water-based mud filtrate in accordance with oneembodiment of the present disclosure;

FIG. 8 shows a plot that was generated by optically analyzing aformation fluid sample that was separated using a membrane in accordancewith one embodiment of the present disclosure;

FIG. 9 shows an original oil sample, an emulsion of the original oilsample and water, and a sample after the emulsion has been passedthrough a membrane in accordance with one embodiment of the presentdisclosure;

FIG. 10 shows a wireline log that was obtained using a rapid formationfluid analysis method in accordance with one embodiment of the presentdisclosure;

FIG. 11 shows a concurrent wireline log that was obtained using aconventional fluid analysis system;

FIG. 12 shows a plot that was obtained using a rapid formation fluidanalysis method in accordance with one embodiment of the presentdisclosure;

FIG. 13 shows optical spectra for a set of single phase fluids; and

FIG. 14 shows one potential spectrum generated from a 50 percent oil andwater mixture.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

Illustrative embodiments of the disclosure are directed to a method fordetermining a property of a formation. The method includes positioning awellbore tool at a location within a wellbore. The tool withdraws theformation fluid from the formation at the location. The formation fluidpasses through a flow line within the wellbore tool and a formationfluid sample is extracted from the flow line. The method furtherincludes performing an analysis of the formation fluid sample within thewellbore tool by excluding mud filtrate contamination within the flowline. In contrast to past methods, the analysis can be performed beforemud filtrate contamination within the flow line has cleaned up. In thismanner, embodiments described herein perform a “rapid” formation fluidanalysis and avoid extended clean up times and increase efficiency ofwireline logging, logging-while-drilling (LWD), and other operations.Details of various embodiments are discussed below.

FIG. 1 shows one example of a wireline logging system 100 at a wellsite. Such a wireline logging system 100 can be used to implement arapid formation fluid analysis. In this example, a wireline tool 102 islowered into a wellbore 104 that traverses a formation 106 using a cable108 and a winch 110. The wireline tool 102 is lowered down into thewellbore 104 and makes a number of measurements of the adjacentformation 106 at a plurality of sampling locations along the wellbore104. The data from these measurements is communicated through the cable108 to surface equipment 112, which may include a processing system forstoring and processing the data obtained by the wireline tool 102. Thesurface equipment 112 includes a truck that supports the wireline tool102. In other embodiments, the surface equipment may be located in otherlocations, such as within a cabin on an off-shore platform.

FIG. 2 shows a more detailed view of the wireline tool 102. The wirelinetool includes 102 a selectively extendable fluid admitting assembly(e.g., probe) 202. This assembly 202 extends into the formation 106 andwithdraws formation fluid from the formation 116 (e.g., samples theformation). The fluid flows through the assembly 202 and into a mainflow line 204 within a housing 206 of the tool 102. A pump module 207 isused to withdraw the formation fluid from the formation 106 and pass thefluid through the flow line 204. The wireline tool 102 may include aselectively extendable tool anchoring member 208 that is arranged topress the probe 202 assembly against the formation 106.

The wireline tool 102 also includes a fluid analyzer module 210 foranalyzing at least a portion of the fluid in the flow line 204. Thisfluid analyzer module 210 is further described below. After the fluidanalysis module 210, the formation fluid may be pumped out of the flowline 204 and into the wellbore 104 through a port 212. Some of theformation fluid may also be passed to a fluid collection module 214 thatincludes chambers for collecting fluid samples and retaining samples ofthe formation fluid for subsequent transport and testing at the surface(e.g., at a testing facility or laboratory).

FIG. 3A shows a more detailed view of a fluid analyzer module 210. Asshown in FIG. 3A, the fluid analyzer module 210 includes a secondaryflow line 302 (e.g., a channel) that is coupled through a valve 304 tothe main flow line 204. The valve 304 selectively passes a sample offormation fluid into the secondary flow line 302. The secondary flowline 302 also includes a membrane 306 to separate water from theformation fluid sample (e.g., a hydrophobic membrane). Such a membraneis described in U.S. Pat. No. 7,575,681 issued on Aug. 18, 2009 and U.S.Pat. No. 8,262,909 issued on Sep. 11, 2012. Each of these references ishereby incorporated by reference in their entireties.

In some embodiments, a pump or a piston (not shown) can be used toextract the formation fluid sample from the main flow line 204 and passthe formation fluid through the membrane 306. In various embodiments,the membrane 306 separates water from the formation fluid sample as thesample is being extracted from the main flow line 304. Also, in someembodiments, the membrane 306 is disposed before the valve 304. Once theformation fluid sample passes the membrane 306, the sample flows into afluid analyzer 308 that analyzes the sample to determine at least oneproperty of the fluid sample. The fluid analyzer 308 is in electroniccommunication with the surface equipment 112 through, for example, atelemetry module (not shown) and the cable 108. Accordingly, the dataproduced by the fluid analyzer 308 can be communicated to the surfacefor further processing by processing system.

The fluid analyzer 308 can include a number of different devices andsystems that analyze the formation fluid sample. For example, in oneembodiment, the fluid analyzer 308 includes a spectrometer that useslight to determine a composition of the formation fluid sample. Thespectrometer can determine an individual fraction of methane (C₁), anindividual fraction of ethane (C₂), a lumped fraction of alkanes withcarbon numbers of three, four, and five (C₃-C₅), and a lumped fractionof alkanes with a carbon number equal to or greater than six (C₆₊). Anexample of such a spectrometer is described in U.S. Pat. No. 4,994,671issued on Feb. 19, 1991 and U.S. Patent Application Publication No.2010/0265492 published on Oct. 21, 2012. Each of these references ishereby incorporated by reference, in their entireties, herein. Inanother embodiment, the fluid analyzer 308 includes a gas chromatographthat determines a composition of the formation fluid. In one embodiment,the gas chromatograph determines an individual fraction for each alkanewithin a range of carbon numbers from one to 25 (C₁-C₂₅). Examples ofsuch gas chromatographs are described in U.S. Pat. No. 8,028,562 issuedon Oct. 4, 2011 and U.S. Pat. No. 7,384,453 issued on Jun. 10, 2008.Each of these references is hereby incorporated by reference, in theirentireties, herein. The fluid analyzer 308 may also include a massspectrometer, a visible absorption spectrometer, an infrared absorptionspectrometer, a fluorescence spectrometer, a resistivity sensor, apressure sensor, a temperature sensor, a densitometer and/or aviscometer. The fluid analyzer 308 may also include combinations of suchdevices and systems. For example, the fluid analyzer module 210 mayinclude a spectrometer followed by a gas chromatograph as described in,for example, U.S. Pat. No. 7,637,151 issued on Dec. 29, 2009 and U.S.patent application Ser. No. 13/249,535 filed on Sep. 30, 2011. Each ofthese references is hereby incorporated by reference, in theirentireties, herein.

FIG. 3B shows a fluid analyzer module 210 in accordance with anotherembodiment of the present disclosure. In this embodiment, a bypass flowline 301 is coupled to the main flow line 204 through a first valve 305.The first valve 305 selectively passes formation fluid from the mainflow line 204 into the bypass flow line 301. A secondary flow line 307(e.g., a channel) is coupled through a second valve 309 (e.g., anentrance valve) to the bypass flow line 301. The second valve 309selectively passes a sample of formation fluid into the secondary flowline 307. The fluid analyzer module 204 includes a membrane 311 toseparate water from the formation fluid sample (e.g., a hydrophobicmembrane). In this embodiment, the membrane 311 is disposed before thesecond valve 309. The fluid analyzer module 210 also includes a thirdvalve 313 (e.g., an exit valve) between the secondary flow line 307 andthe bypass flow line 301. The second valve 309 and the third valve 313can be used to isolate the formation fluid sample within the secondaryflow line 307. After analysis, the formation fluid sample can pass tothe bypass flow line 301 through the third valve 313.

In this specific embodiment, the fluid analyzer module 210 furtherincludes a spectrometer 315 followed by a densitometer 317 and aviscometer 319. Such an arrangement will provide both a chemicalcomposition for the fluid sample and also physical characteristics forthe fluid sample (e.g., density and viscosity). As explained above,other combinations of devices and systems that analyze the formationfluid sample are also possible.

In FIG. 3B, the fluid analyzer module 210 also includes a pressure unit321 for changing the pressure within the fluid sample and a pressuresensor 323 that monitors the pressure of the fluid sample within thesecondary flow channel 307. In one specific embodiment, the pressureunit 321 is a piston that is in communication with the secondary flowline 307 and that expands the volume of the fluid sample to decrease thepressure of the sample. As explained above, the second valve 309 and thethird valve 313 can be used to isolate the formation fluid sample withinthe secondary flow line 307. Also, in some embodiments, the pressureunit 321 can be used to extract the formation fluid sample from thebypass flow line 301 by changing the pressure within the secondary flowline 307. The pressure sensor 323 is used to monitor the pressure of thefluid sample within the secondary flow line 307. The pressure sensor 323can be a strain gauge or a resonating pressure gauge. By changing thepressure of the fluid sample, the fluid analyzer module 210 can makemeasurements related to phase transitions of the fluid sample (e.g.,bubble point or asphaltene onset pressure measurements). Further detailsof devices and systems that analyze the formation fluid sample are alsoprovided in U.S. Provisional Patent Application Ser. No. 61/______entitled “Pressure Volume Temperature System” and filed on Mar. 14, 2013(Attorney Docket No. IS13.3119-US-PSP), which is hereby incorporated byreference, in its entirety, herein.

FIG. 4 shows a method 400 for determining a property of a formation inaccordance with one embodiment of the present disclosure. As shown atprocess 402, the method 400 includes positioning a wellbore tool at afirst location within a wellbore. In some embodiments, this wellboretool is the wireline tool 102, as shown in FIG. 2. However, in variousother embodiments, the wellbore tool can also be alogging-while-drilling tool. Once positioned adjacent to alocation-of-interest within the formation, at process 404, the wellboretool withdraws the formation fluid from the formation (e.g., samples theformation). The wellbore tool can use a selectively extendable fluidadmitting assembly 202, as shown in FIG. 2, to withdraw the formationfluid from the formation. The formation fluid then passes through a mainflow line within the wellbore tool. In some embodiments, the formationfluid is pumped through the main flow line using the pump module 207. Atprocess 406, a formation fluid sample is extracted from the main flowline. In one example, as shown in FIG. 3, the valve 304 is open betweenthe main flow line 204 and the secondary flow line 302 so that aformation fluid sample passes into the secondary flow line of the fluidanalyzer module 210. In other embodiments, the formation fluid sample isextracted from a different flow line, such as bypass flow line 301. Atprocess 408, an analysis of the formation fluid sample is performedwithin the wellbore tool to determine a property of the formation fluidsample. This analysis is performed by, for example, the fluid analyzermodule 210, as shown in FIGS. 2 and 3.

At process 408, the analysis of the formation fluid is performed byexcluding the mud filtrate contamination within the flow line (e.g., themain flow line 204). As explained above, when the wellbore toolwithdraws formation fluid from the formation, the fluid initiallyincludes mud filtrate contamination. Reference number 216 within FIG. 2shows mud filtrate contamination within the formation 106. According topast methods, the wellbore tool continues to withdraw and pump formationfluid out of the formation until the fluid within the main flow line has“cleaned up.” One measure for determining whether the formation fluidhas cleaned up is the stability of the ratio of formation water to oilwithin the flow line. After the formation fluid has cleaned up, theclean formation fluid can be analyzed. Thus, in the past, the approachto formation fluid analysis was dependent on clean formation fluidwithin the flow line. In contrast, the rapid formation fluid analysismethod described herein performs an analysis of the formation fluidindependent of mud filtrate contamination within the flow line byexcluding the mud filtrate contamination within the flow line. Theanalysis can be performed before the formation fluid within the mainflow line has “cleaned up” and while there is still substantial mudfiltrate contamination. Substantial mud filtrate contamination can rangebetween 5 percent and 99 percent of the fluid within the main flow line.Accordingly, embodiments of the rapid formation fluid analysis methodavoid long cleanup times and reduce costs associated with wireline andLWD logging operations, Various embodiments also facilitate wireline andLWD logging measurements that would otherwise be prohibitively expensiveor pose an excessive risk for “sticking” the wellbore logging systemagainst the wellbore wall.

The rapid formation fluid analysis method can be applied to formationsthat are contaminated by oil-based drilling muds or water-based drillingmuds. For example, FIG. 5 shows a method 500 for determining a propertyof a formation that is contaminated by an oil-based mud filtrate. Themethod 500 of FIG. 5 includes positioning a wellbore tool at a firstlocation within a wellbore 502, withdrawing a formation fluid from theformation and passing the formation fluid through a flow line within thetool 504, and extracting a formation fluid sample from the flow line506. The method 500 further includes identifying a plurality of chemicalcomponents within the formation fluid sample using gas chromatography508. In this embodiment, the fluid analyzer module includes a gaschromatograph that determines the chemical composition of the fluidsample. In one particular embodiment, the chromatograph determines theindividual chemical components of the fluid sample from C₁ to C₂₅. Atprocess 510, chemical components that constitute the oil-based mudfiltrate are excluded from consideration. In one specific example, oneor more chemical components with carbon numbers between C₈ and C₂₀ areexcluded from consideration. At process 512, the remaining set ofchemical components (e.g., C₁-C₇ and C₂₁₊) is used to determine theproperty of the formation. In this manner, the method analyzes theformation fluid sample independently of oil-based mud filtratecontamination within the flow line. Those chemical components that makeup the mud filtrate are not used in the analysis and thus do notinvalidate or adversely impact the analysis.

As explained above, chemical components can be excluded fromconsideration based upon the composition of the oil-based drilling mud.In some cases, the chemical composition of the drilling mud is known andthose specific chemical components that constitute the oil-baseddrilling mud are excluded from consideration. To this end, the chemicalcomposition of certain types of drilling muds can be obtained from adatabase that includes various types of drilling muds and their chemicalcomponents. Also, the drilling mud can be analyzed at a surface locationusing gas chromatography to determine its chemical components. In oneexample, C₁₃ and C₁₅-C₁₈ are known chemical components of the drillingmud and those chemical components are excluded from consideration.

FIG. 6A shows a “contaminated” chromatogram 602 that was obtained byanalyzing a formation fluid sample contaminated with an oil-based mudfiltrate. In this case, the formation fluid sample included 50 percentcontamination with an oil-based mud filtrate. The oil-based mud filtrateincluded chemical components with carbon numbers between C₁₅ to C₁₈ andthose components are represented as enlarged peaks within thechromatogram. Per process 510 of FIG. 5, the C₁₅ to C₁₈ chemicalcomponents and representative peaks are removed from consideration andnot used to determine the properties of the fluid sample. FIG. 6A alsoshows a reference chromatogram 604 that was obtained by analyzing aformation fluid sample that was uncontaminated by the oil-based mudfiltrate. The enlarged peaks representative of the oil-based mudfiltrate do not appear within the reference chromatogram 604.

FIG. 6B shows a more detailed view of the chromatograms 602, 604 of FIG.6A. In particular, FIG. 6B shows the representative peaks of componentswith carbon numbers from C₁ to C₇. The representative peaks within thecontaminated chromatogram 602 match the representative peaks within thereference chromatogram 604. The peaks within the contaminatedchromatogram 602 are smaller than the representative peaks within thereference chromatogram 604 due to the smaller quantity of originalformation fluid in the contaminated chromatogram. As explained above,the contaminated sample included 50 percent contamination from oil-basedmud filtrate. FIGS. 6A and 6B show that the representative peaks from C₁to C₇ within the contaminated chromatogram 602 can be reliably used todetermine a property of the formation fluid sample because they matchthe representative peaks within the reference chromatogram 604. Morespecifically, the representative peaks from C₁ to C₁₄ and therepresentative peaks greater than C₁₈ can be used to determine aproperty of the formation fluid sample because those areas of thechromatogram were not affected by the oil-based mud filtrate.

In some embodiments, when the specific chemical components of thedrilling mud are unknown, a broader range of chemical components can beexcluded from consideration. In one example, chemical components withcarbon numbers between C₈ and C₂₀ are excluded because drilling mudsgenerally include chemical components with carbon numbers between C₈ andC₂₀. Oil-based drilling muds are often made from diesel, a distillationfraction or synthetic oil. Such oil-based muds have a limited carbonnumber range. Typically, the lowest carbon number observed is C₁₀ orC₁₁, but some diesel and distillation based muds will start at C₈ or C₉.Other oil-based muds, such as synthetic oil-based muds, are much moremonodisperse and have a higher carbon number anywhere from C₁₂ to C₁₆.The highest carbon number in an oil-based drilling mud is more variableand ranges from C₁₄, for some lighter muds, to C₂₉, for some of thedistillate-based muds. Generally, the end point for carbon numbers isbetween C₁₆ and C₂₀. Accordingly, on the higher end, there are smallconcentrations of components above the C₂₀ endpoint within drilling mudsand, at the lower end, there are very small concentrations of componentsbelow C₈.

The method 500 of FIG. 5 will provide a partial chemical composition ofthe formation fluid within the formation (e.g., individual C₁-C₇ andC₂₁₊ fractions). In turn, this chemical composition information can beused to determine a property of the formation (e.g., a hydrocarbonreservoir). In one example, the partial chemical composition itself is aproperty of the formation and provides information about the differenttypes of hydrocarbons present within the formation. The partial chemicalcomposition can also be used to determine other properties of theformation. For example, the lighter individual hydrocarbon fractions(e.g., C₁-C₇) that remain for consideration can provide valuableinformation about the properties of the formation. Specifically, C₇isomers are separated using gas chromatography and the C₇ isomer ratiocan be used to determine the source of the hydrocarbons within theformation, the maturity of the hydrocarbons, the biodegradation of thehydrocarbons, the fractionation of the hydrocarbons, the water washingof the hydrocarbons, and/or thermochemical sulfate reduction of thehydrocarbons, as described in, for example, Peters et al., The BiomarkerGuide, Vol. 1, pp. 162-190 (2007). In particular, a decreased ratio oftoluene over n-heptane indicates water washing and proximity of a waterzone. An increase of the cyclopentanes over n-heptane indicatesbiodegradation. In another example, the chemical components from C₁ toC₅ can be used to determine wetness ratios, balance ratios, andcharacter ratios as described in Haworth et al., Interpretation ofHydrocarbon Shows Using Light (C₁-C₅) Hydrocarbon Gases From Mud LogData, AAPG Vol. 69, pp. 1305-1310 (1985). In yet another example, theratios between the C₁, C₂, C₃ and C₄ components (e.g., elevated (C₁)levels in particular) can be used to determine the presence of secondarycharging or biodegradation.

The heavier individual fractions (e.g., C₂₁₊) including biomarkers thatremain for consideration can also provide valuable information about theproperties of the formation. For example, biomarkers can be used todetermine properties of the formation. Biomarkers are complex organiccompounds that are disposed in sediments, rocks, and crude oils and showlittle or no change in chemical structure from their original parentorganic molecules, which were part of living organisms. Biomarkers canbe used to determine the history of the oil within the formation. Inparticular, biomarkers can be used to identify oil-oil and oil-sourcerock correlations and thermal maturity. Ptystane and phytane are acyclicisoprenoid biomarkers that elute around C₁₇ and C₁₈. Other biomarkerswill elute between C₂₄ and C₃₆, such as hopanes, which elute around C₂₇to C₂₉. Further details about how biomarkers can be used to determineproperties of formation are described in Peters et al., The BiomarkerGuide, Vol. 2, pp. 473-640, 645-703 (2007).

The rapid formation fluid analysis method can also be applied toformations that are contaminated by water-based drilling muds. Forexample, FIG. 7 shows a method 700 for determining a property of aformation that is contaminated by a water-based mud filtrate. The method700 of FIG. 7 includes positioning a wellbore tool at a first locationwithin a wellbore 702, withdrawing a formation fluid from the formationand passing the formation fluid through a flow line within the wellboretool 704, and extracting a formation fluid sample from the flow line 706(e.g. the main flow line 204 or bypass flow line 301). At process 708,the method 700 further includes removing water from the formation fluidsample by passing the formation fluid sample through a membrane. Thismembrane may be a hydrophobic membrane that separates a water fractionfrom an oil fraction, such as the membrane 306 shown in FIG. 3.Furthermore, processes 706 and 708 may happen simultaneously. Then, atprocess 710, the formation fluid sample is analyzed within the wellboretool to determine a property of the formation. In one example of themethod, the fluid analyzer is a spectrometer and the analyzing process710 is performed to measure the C₁, C₂, lumped C₃-C₅, and lumped C₆₊fractions within the formation fluid sample. This analysis is performedindependently of water-based mud filtrate contamination within the flowline because the membrane removes the water before the formation fluidsample enters the fluid analyzer. Accordingly, the method can analyzethe formation fluid sample before the water filtrate within the flowline has cleaned up.

As explained above, the membrane removes water filtrate from theformation fluid sample and improves the accuracy of the fluid analyzer.In various embodiments, the purpose of performing the fluid analysis onthe formation fluid is to determine the chemical components of thehydrocarbon fraction within the formation fluid sample (e.g., the C₁,C₂, lumped C₃-C₅, and lumped C₆₊ fractions). The presence of waterwithin the sample can adversely impact this analysis. For example, whenperforming an optical analysis using a spectrometer, the water withinthe sample scatters the light signal from the spectrometer and generatesartifacts within the detected light signal. In other systems, softwarecan be used to remove these artifacts. In some cases, however, the waterfraction and the hydrocarbon fraction can create an emulsion. Emulsionsthat appear within the flow line may be difficult to cleanup even withextended cleanup times and the artifacts they generate in detected lightsignals can be very difficult to remove. In various embodiments, themembrane advantageously separates the water fraction from thehydrocarbon fraction. In this manner, the optical analysis can beperformed on a single phase hydrocarbon sample without interference fromother phases (e.g., a water fraction).

Illustrative embodiments of the rapid formation analysis method can beused to reliably produce a formation fluid sample that accuratelyrepresents the original hydrocarbon fraction within the formation. FIG.8 shows a plot 806 that was generated by optically analyzing a formationfluid sample that was separated using the membrane. In particular, threedifferent plots are shown within FIG. 8. Plot 802 represents the opticalspectrum for a heavy oil and plot 804 shows the optical spectrumproduced by an emulsion of water and the same heavy oil. As the plotsshow, the water has a substantial impact on the optical diffraction ofthe sample and many optical characteristics of the original crude oilare lost. Plot 806 shows the optical spectrum produced by the separatedheavy oil. To produce plot 806, the emulsion of water and the heavy oilwas passed through the membrane and then optically analyzed. Plot 806 isnearly identical to the plot 802 produced by the original heavy oil.FIG. 8 shows that the membrane can be reliably used to remove the waterfraction and to produce a formation fluid sample that accuratelyrepresents the original hydrocarbon fraction within the formation.

FIG. 9 shows a series of oils samples. Sample 902 is an original oilsample, sample 904 is an emulsion of the original oil sample and waterand sample 906 represents a sample after the emulsion has been passedthrough the membrane. FIG. 9 shows how a membrane can be used to returna formation fluid sample to a state that accurately represents theoriginal hydrocarbon fraction within the formation.

Various embodiments of the rapid formation analysis method can be usedto accurately detect and analyze the hydrocarbon fraction of formationfluids. FIG. 10 shows a wireline log 1000 that was obtained using arapid formation fluid analysis method. In particular, the log 1000 inFIG. 10 was obtained using a spectrometer disposed behind a hydrophobicmembrane. FIG. 11 shows a concurrent wireline log 1100 that was obtainedusing a spectrometer-based conventional fluid analysis system. Acomparison between FIGS. 10 and 11 shows the ability of the membrane toproduce a stable optical measurement. The wireline log 1100 in FIG. 11shows a live plot of oil and water fractions. Reference number 1102refers to areas with large fluctuations of water and reference number1104 refers to areas with large fluctuations in oil. In some cases, theconventional fluid analysis system yields data where the oil and waterfraction add up to greater than one. This means that the data in theseareas in the log 1100 is generally not reliable. Reference number 1106refers to such areas on the wireline log 1100. Such areas 1106 are anindication of very high optical scattering due to mud filtrate insidethe flow line. In contrast, the wireline log 1000 in FIG. 10 shows awireline log 1000 that was obtained using a 4 channel spectrometerdisposed behind a hydrophobic membrane. The wireline log includes plots1002, 1004, 1006, 1008 for each channel of the spectrometer. As shown bythe plots, even when the conventional system fails to detect oil (e.g.,around time mark 1071.0 on the wireline log 1100), the 4 channelspectrometer records a signal that can be used to determine thecomposition of the oil. This comparison shows that the combination ofthe membrane and spectrometer can detect much smaller optical oilsignatures, as compared to the conventional system. FIG. 10 furthershows that the oil signal is stable for the next 1.8 hours, whereas theconventional system shows heavy fluctuation of oil and water.

FIG. 12 shows another example of how the rapid formation analysis methodcan be used to accurately detect and analyze the hydrocarbon fraction offormation fluids. In this example, the rapid formation fluid analysismethod was implemented by a wireline tool with a selectively extendablefluid admitting assembly (e.g., probe). In particular, three differentplots are shown within FIG. 12. Plot 1202 represents an optical spectrumgenerated by a spectrometer that was located near the probe of thewireline tool before a pump (e.g., after probe 202 and before pumpmodule 207 in FIG. 2). The spectrometer before the pump analyzes aninitial formation fluid that is free of a water/oil emulsion.Accordingly, plot 1202 has a low optical density baseline with noevidence of optical scattering. The second plot 1204 represents anoptical spectrum generated by a second spectrometer that is disposedfurther downstream after the pump within the wireline tool (e.g., afterpump module 207 in FIG. 2). This second spectrometer produces a largeincrease in optical scattering because the pump churns up oil and waterwithin the formation fluid and produces a highly scattering emulsion.Plot 1206 represents an optical spectrum generated by a thirdspectrometer that was also located after the pump (e.g., after pumpmodule 207 in FIG. 2). This third spectrometer, however, was disposedafter a hydrophobic membrane that removed water from the formation fluidsample. As shown by plot 1206, the rapid formation analysis methodaccurately reproduces the optical spectrum 1202 generated by the initialemulsion-free formation fluid.

Various embodiments of the rapid formation analysis method can also beused to accurately determine a fluid color for hydrocarbon fractionswithin formation fluids. The fluid color of a formation fluid is usedfor fluid typing (e.g., determining the presence of water, gas,condensate, light oil, medium oil, and/or heavy oil). In anotherexample, the fluid color is used to quantify the oil-based mud filtratecontamination within the formation fluid. Fluid color measurements maybe influenced by the presence of water (e.g., from a water-based mudfiltrate). FIG. 13 shows optical spectra for a set of single phasefluids, such as water, heavy oil, medium oil, etc. The optical spectrumthat results from a mixture of oil and water depends on (1) the oil andwater fraction and (2) how the fluids mix together. FIG. 14 shows onepotential spectrum generated from a 50 percent oil and water mixture.The mixture had a multi-phase flow with slugs of oil and slugs of water(e.g., a “sluggy” flow). As compared with FIG. 13, the oil color isaffected dramatically by the presence of water. In particular, themethane absorption peak (C₁) is quite weak and can be masked in thepresence of water. By applying the rapid formation analysis method, thewater can be removed from the formation fluid and a more accurate colorof the formation fluid can be obtained.

With respect to water-based drilling muds, the rapid formation fluidanalysis method is not limited to any particular type of fluid analysistechnique. Optically analyzing formation fluid samples using aspectrometer is one example. In other embodiments, gas chromatographycan be used to determine the individual C₁ to C₂₅ fractions of theformation fluid sample. For example, in one specific embodiment, thefluid analyzer module, as shown in FIG. 3, includes a gas chromatograph.This fluid analyzer configuration can be used to analyze formation fluidcontaminated with both water-based mud filtrates and oil-based mudfiltrates. When analyzing a formation fluid with water basedcontamination, the hydrophobic membrane removes the water from theformation fluid and the gas chromatograph analyzes the formation fluidsample to determine the individual C₁ to C₂₅ fractions within theformation fluid sample. In the case when the mud filtrate is anoil-based mud filtrate, the gas chromatograph analyzes the formationfluid sample to determine the individual C₁ to C₂₅ fractions within theformation fluid sample and the chemical components that constitute theoil-based mud filtrate are excluded from consideration. In this case,although the hydrophobic membrane does not prevent oil-based mudfiltrate from passing to the gas chromatograph, the membrane doesadvantageously protect the gas chromatograph from water, which candamage stationary phases within the gas chromatograph. In yet furtherembodiments, one of mass spectroscopy, visible absorption spectroscopy,infrared absorption spectroscopy, fluorescence detection, bubble pointmeasurements, dew point measurements, asphaltene onset pressuremeasurements, resistivity measurements, fluid pressure measurements,fluid density measurements, fluid viscosity measurements, and fluidtemperature measurements can also be used to analyze the formation fluidsample. Combinations of such techniques may also be used.

The rapid formation analysis method can be implemented a number ofdifferent ways in order to increase the efficiency of logging operationsand provide valuable information about the formation. In one example, awireline tool performs a rapid formation fluid analysis at a pluralityof sampling locations within the wellbore. In so doing, the loggingoperation avoids cleanup time at each sampling location, while alsoproviding valuable information about the formation at each location.More specifically, the rapid formation analysis provides a partialchemical composition of the formation fluid at each of the samplinglocations. Such a partial chemical composition indicates the presence ofdifferent types of hydrocarbons within the formation and shows how thosetypes of hydrocarbons change between the different sampling locations.In one example, the C₁, C₂, lumped C₃-C₅, and lumped C₆₊ fractions froman optical analysis can be used for fluid typing and determiningconnectivity within the formation. In another example, the lighterindividual hydrocarbon fractions (e.g., C₁-C₇) from a gas chromatographyanalysis can be used to determine the source of the hydrocarbons withinthe formation, the maturity of the hydrocarbons, the biodegradation ofthe hydrocarbons, the fractionation of the hydrocarbons, the waterwashing of the hydrocarbons, and thermochemical sulfate reduction of thehydrocarbons.

In various embodiments, the partial chemical compositions at each of thesampling locations are compared against each other to determine otherproperties of the formation, such as connectivity within the formation.By using ratios of certain chemical components at the samplinglocations, a comparison can be made between different sampling locationsto determine whether the sampling locations are connected. For example,the ratio between heptane and methylcyclohexane can be used to determineconnectivity. In another specific example, a ratio between heptane and atotal amount of dimethylcyclopentanes (or an individual amount of adimethylcyclopentane) can be used to determine connectivity. Samplinglocations with similar chemical compositions are likely connected. Suchcomparisons can be made (1) between one or more sampling locationswithin the same wellbore, (2) between one or more sampling locationswithin different wellbores of the same multilateral well, and (3)between one or more sampling locations within different wells.

In some embodiments, the rapid formation analysis method can be used todetermine whether to perform a more comprehensive analysis of theformation at a sampling location. In such embodiments, the wireline toolperforms a comprehensive analysis of the formation at a first samplinglocation. In one example, the comprehensive analysis includes analyzingan uncontaminated fluid sample. To this end, the wellbore tool withdrawsthe formation fluid from the formation and pumps the formation fluidthrough the flow line until the formation fluid within the flow line isuncontaminated by mud filtrate. In one specific example, the flow lineis the main flow line represented by reference number 204 in FIG. 2.Once the formation fluid is uncontaminated, the analysis of theformation fluid is performed. The analysis of the uncontaminatedformation fluid can be performed within the main flow line or theuncontaminated formation fluid can be extracted from the main flow lineinto a secondary flow line and analyzed within the secondary channel. Inanother example, the comprehensive analysis includes extracting anuncontaminated formation fluid sample from the flow line and thentransporting the uncontaminated formation fluid sample for surfaceanalysis.

The more comprehensive analysis of the formation fluid at the firstsampling location can provide additional information, such as a waterfraction for the formation fluid or more complete chemical compositionidentification (e.g., a complete set of individual fractions for C₁ toC₂₅). As explained above, however, the disadvantage of this morecomprehensive analysis is the additional clean up time. The rapidformation analysis method can be applied at the next sampling locationto increase the efficiency of the logging operation. For example, thewellbore tool is moved to a second sampling location and the rapidformation analysis method is performed to determine a partial chemicalcomposition of the formation fluid. By comparing the partial chemicalcomposition at the second sampling location to the more completechemical composition at the first sampling location, the connectivitybetween the sampling locations can be determined. If there is noconnectivity between the two sampling locations, then a morecomprehensive analysis at the second sampling location can be performed(e.g., an analysis of an uncontaminated formation fluid). If there isconnectivity between the two sampling locations, then a determinationthat the two sampling locations have similar formation properties can bemade and the wellbore tool does not perform a more comprehensiveanalysis at the second sampling location. Instead, the wellbore toolmoves on to analyze the formation at a third sampling location. Thisprocess can be repeated iteratively. In this manner, the rapid formationanalysis method can be used to avoid acquisition of redundant data atmultiple sampling locations, which, in turn, also increases loggingefficiency.

Illustrative embodiments of the present disclosure are not limited towireline logging operations, such as the ones shown in FIGS. 1-3. Forexample, the embodiments described herein can also be used with anysuitable means of conveyance, such coiled tubing. Furthermore, variousembodiments of the present disclosure may also be applied inlogging-while-drilling (LWD) operations, sampling-while-drillingoperations, measuring-while-drilling operations or any other operationwhere sampling of the formation is performed.

Some of the processes described herein, such as (1) determining aproperty of the formation fluid sample, (2) determining a property of aformation, (3) excluding chemical components that constitute oil-basedmud filtrate, (4) using a set of remaining chemical components todetermine a property of a formation fluid sample, (5) determiningwhether to perform an analysis of an uncontaminated formation fluidusing a property of a formation fluid sample, and (6) comparing aproperty of a formation fluid sample at a first location to a propertyof a second formation fluid sample at a second location, can beperformed by a processing system.

In one specific embodiment, the processing system is located at the wellsite as part of the surface equipment (e.g., the truck 112 in FIG. 1).The processes are performed at the well site using the processing systemwithin the truck. In other embodiments, however, the processes may beperformed at a location that is remote from the well site, such as anoffice building or a laboratory.

The term “processing system” should not be construed to limit theembodiments disclosed herein to any particular device type or system. Inone embodiment, the processing system includes a computer system. Thecomputer system may be a laptop computer, a desktop computer, or amainframe computer. The computer system may include a graphical userinterface (GUI) so that a user can interact with the computer system.The computer system may also include a computer processor (e.g., amicroprocessor, microcontroller, digital signal processor, or generalpurpose computer) for executing any of the methods and processesdescribed above (e.g. processes (1)-(6)).

The computer system may further include a memory such as a semiconductormemory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-ProgrammableRAM), a magnetic memory device (e.g., a diskette or fixed disk), anoptical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card),or other memory device. This memory may be used to store, for example,data from the wellbore tool.

Some of the methods and processes described above, including processes(1)-(6), as listed above, can be implemented as computer program logicfor use with the computer processor. The computer program logic may beembodied in various forms, including a source code form or a computerexecutable form. Source code may include a series of computer programinstructions in a variety of programming languages (e.g., an objectcode, an assembly language or a high-level language such as C, C++ orJAVA). Such computer instructions can be stored in a non-transitorycomputer readable medium (e.g., memory) and executed by the computerprocessor. The computer instructions may be distributed in any form as aremovable storage medium with accompanying printed or electronicdocumentation (e.g., shrink wrapped software), preloaded with a computersystem (e.g., on system ROM or fixed disk), or distributed from a serveror electronic bulletin board over a communication system (e.g., theInternet or World Wide Web).

Additionally, the processing system may include discrete electroniccomponents coupled to a printed circuit board, integrated circuitry(e.g., Application Specific Integrated Circuits (ASIC)), and/orprogrammable logic devices (e.g., a Field Programmable Gate Arrays(FPGA)). Any of the methods and processes described above can beimplemented using such logic devices.

Although several example embodiments have been described in detailabove, those skilled in the art will readily appreciate that manymodifications are possible in the example embodiments without materiallydeparting from the scope of this disclosure. Accordingly, all suchmodifications are intended to be included within the scope of thisdisclosure.

What is claimed is:
 1. A method for determining a property of aformation, the method comprising: positioning a tool at a first locationwithin a wellbore; withdrawing a formation fluid from the formation atthe first location using the tool, wherein the formation fluid passesthrough a flow line within the tool; extracting a formation fluid samplefrom the flow line; and analyzing the formation fluid sample within thetool by excluding mud filtrate contamination within the flow line. 2.The method according to claim 1, wherein analyzing comprises: removingwater from the formation fluid sample by passing the formation fluidsample through a membrane when the mud filtrate is a water-based mudfiltrate.
 3. The method according to claim 2, wherein the analysis ofthe formation fluid sample is selected from the group consisting of: gaschromatography, mass spectroscopy, visible absorption spectroscopy,infrared absorption spectroscopy, fluorescence detection, resistivitymeasurements, pressure measurements, density measurements, viscositymeasurements, temperature measurements, and a combination thereof. 4.The method according to claim 1, wherein the analyzing comprises:analyzing the formation fluid sample using gas chromatography when themud filtrate is an oil-based mud filtrate.
 5. The method according toclaim 4, wherein analyzing comprises: identifying a plurality chemicalcomponents within the formation fluid sample; excluding chemicalcomponents that comprise the oil-based mud filtrate; and determining theproperty of the formation fluid sample.
 6. The method according to claim5, wherein at least one chemical component with a carbon number between8 and 20 is excluded from consideration.
 7. The method according toclaim 5, further comprising: using a known chemical composition of themud filtrate to exclude chemical components that comprise the oil-basedmud filtrate.
 8. The method according to claim 1, further comprising:using the property of the formation fluid sample to determine whether toperform an analysis of an uncontaminated formation fluid within the flowline.
 9. The method according to claim 8, wherein the analysis of theuncontaminated formation fluid comprises: withdrawing the formationfluid from the formation and pumping the formation fluid through theflow line until the formation fluid within the flow line isuncontaminated by mud filtrate; and performing an analysis of theuncontaminated formation fluid within the tool.
 10. The method accordingto claim 8, wherein the analysis of the uncontaminated formation fluidcomprises: withdrawing the formation fluid from the formation andpumping the formation fluid through the flow line until the formationfluid within the flow line is uncontaminated by mud filtrate; andextracting an uncontaminated formation fluid sample from the flow line;transporting the uncontaminated formation fluid sample for surfaceanalysis.
 11. The method according to claim 1, further comprising:comparing the property of the formation fluid sample at the firstlocation to a property of a second formation fluid sample at a secondlocation within the wellbore; and using the comparison to determinewhether to perform an analysis of an uncontaminated formation fluid atthe first location.
 12. The method according to claim 1, furthercomprising: comparing the property of the formation fluid sample at thefirst location within the wellbore to a property of a second formationfluid sample at a second location; and using the comparison to determinea property of the formation.
 13. The method according to claim 12,wherein the second location is a location selected from the groupconsisting of: a location within the wellbore, a location within asecond wellbore of a second well and a location within a second wellborewithin a multilateral well.
 14. The method according to claim 1, whereinthe property of the formation fluid sample is a chemical composition forthe formation fluid sample and analyzing the formation fluid samplecomprises determining the chemical composition for the formation fluidsample.
 15. The method according to claim 1, wherein the property of theformation fluid sample is selected from the group consisting of: bubblepoint, dew point, asphaltene onset pressure, density, viscosity,pressure, temperature, and a combination thereof.
 16. The methodaccording to claim 1, wherein the property of the formation fluid sampleis used to determine the property of the formation.
 17. The methodaccording to claim 16, wherein the property of the formation is selectedfrom the group consisting of: connectivity, water washing,biodegradation and a combination thereof.
 18. A method for determining aproperty of a formation, the method comprising: positioning a tool at alocation within a wellbore; withdrawing a formation fluid from theformation at the location using the tool, wherein the formation fluidpasses through a flow line within the tool; extracting a formation fluidsample from the flow line; removing water from the formation fluidsample using a membrane; and analyzing the formation fluid sample withinthe wellbore tool to determine a property of the formation fluid sample.19. The method of claim 18, wherein the property of the formation fluidsample is a chemical composition for the formation fluid sample andanalyzing the formation fluid sample comprises determining the chemicalcomposition for the formation fluid sample.
 20. A method for determininga property of a formation, the method comprising: positioning a wellboretool at a location within a wellbore; withdrawing a formation fluid fromthe formation at the location using the wellbore tool, wherein theformation fluid passes through a flow line within the wellbore tool;extracting a formation fluid sample from the flow line; identifying aplurality of chemical components within the formation fluid sample usinggas chromatography; excluding chemical components that comprise anoil-based mud filtrate; and determining the property of the formationfluid sample.